1. Field of the Invention
Embodiments of the invention relate to sensors that measure the capacitance of fluids into which the sensors are immersed, from which the type and the height or level of each of the fluids may be determined. Additionally, methods of using the invention to determine a location or boundary between different types of fluids are disclosed.
2. State of the Art
By way of background, wells, which may include oil, gas, water, or other fluids, are typically drilled through various formations of rocks having different material properties. One of these properties is porosity, which sometimes is defined as the ratio of the volume of empty space to the volume of solid matter in a formation of rock. For example, a sample of a formation of unit size has 0% porosity when the entire space is filled entirely with the solid rock. However, a formation having a porosity of 10% has 10% of the volume filled by a fluid.
In a typical formation having hydrocarbons dispersed in a porous rock, fluids having a low density relative to the other fluids present, such as natural gas, propane, and butane, would be near the “top” of the reservoir rock, or closer to the surface. The hydrocarbons, having a relatively greater density, are typically below the gases. At the lowest portion of the reservoir formation typically lies water because it is denser than the gases and the hydrocarbons.
FIGS. 1 and 2 illustrate a well bore 140 that traverses through several formation layers, 110, 120, and 130. For simplicity, the features of FIGS. 1 and 2 are depicted in two dimensions, however, it will be appreciated that in reality the formation layers 110, 120, 130, the well bore 140, and other features are three dimensional. Formation layer 110 is a “cap rock,” such as shale, that acts as a seal that prevents the in situ formation fluids in the underlying formations from migrating upwards towards the surface. Formation layer 120 is porous rock and a “reservoir layer” in which formation fluids reside within the pore spaces of the formation layer 120. The formation fluids may include a gas layer 122, an oil layer 124, and a water layer 126. The relative volumes of layers 122, 124, and 126 may vary between wells and reservoirs, the important distinction being that in each case the fluids in layers 122, 124, and 126 segregate by density.
A boundary or interface exists at a location where fluids of differing densities meet. For example, the gas-oil interface location 123 demarcates the boundary or interface between the gas layer 122 and the oil layer 124. While the gas-oil interface location 123 appears in FIG. 1 as a straight line, in reality the boundary or interface extends through the formation and is typically non-linear, with variations based on geology, porosity, density, etc. It is merely for convenience and clarity that the gas-oil interface location 123 is depicted as a linear boundary in FIG. 1. Likewise, a boundary exists between the oil layer 124 and the water layer 126 at the oil-water contact location 125a, which demarcates the initial location of the oil-water interface before production of well fluids begins. As discussed more thoroughly below, the locations of the boundaries 123, 125a may change with time and is illustrated in FIG. 1 by the movement of the oil-water contact 125a to location 125b. 
Often, it is desirable to know the location of an interface or boundary between two different fluids in a well, whether it is a water well, brine well (i.e., solution mining), methane/natural gas well, gas wells of other types, observation or injection wells, or petroleum wells. In each instance, but most particularly in the case of a petroleum well, multiple fluids may be present, both liquid and gaseous, and it may be of particular value to know the location of the boundary or interface between the fluids. This is so because it is usually desirable to produce, i.e., pump, to the surface only one or two of those fluids present in the well bore, especially in the case of a petroleum well. (Note: A petroleum well usually has water as well as gas and crude oil present, although the gas or the oil may not be present in commercially viable quantities, i.e. it is desirable to produce only one or the other.)
Unfortunately, water is often produced in a petroleum well. If the water cannot be reinjected in nearby well to improve oil production, it must be treated and disposed of in an environmentally sensitive manner, which may require the use of processes that are expensive. To reduce the amount of water produced and, therefore, reduce the cost of treating that water, it is desirable to know the location of the boundary between the water and the recoverable hydrocarbons present in the well.
The locations of the boundaries of the different fluids typically are determined, at least initially, through the use of logging tools, such as logging while drilling (LWD) tools that take measurements of various formation properties during the drilling of the well and wireline tools that make similar and additional measurements to LWD tools after the well is drilled. The measurements taken by these tools allow for the determination of the type of fluid present in the reservoir formation at a particular depth and, therefore, allow the determination of the location of the boundary between two types of fluids.
However, only that fluid that lies within the pore spaces of the reservoir rock near the well bore can be produced. The distance from the well bore that a fluid may be produced is a function, in part, of the permeability of the reservoir formation (i.e., the degree to which the pore spaces are connected and, thus, provide a path through which the fluid may flow to the well bore), the in-situ pore pressure (the pressure of the fluids in the pore spaces), the hydraulic pressure of the fluid column within the well bore proper, and several other factors known in the art. To form and flow channels to the well bore and, therefore, to increase the likely production of fluids from the pore spaces, the well may be perforated by, for example, the use of explosives. Perforating a well entails the placement of shaped explosive charges at desired locations selected, in part, on the measurement data from LWD and wireline tools and the identified boundary between the fluids. Other methods of increasing the channel to the well bore include hydraulic and acid-fracturing treatments. These treatments, while conceptually different from explosive perforation, use the same principles as explosive perforation to locate the optimum position for conducting the fracturing process. Therefore, for convenience, the discussion herein will refer to explosive perforation, but includes other fracturing processes known in the art.
Based on the initial location of the fluid boundary, a decision is made as to the best location to perforate or fracture the well. For example, the initial oil-water contact location 125a relative to the explosive perforation(s) 170 are indicated in FIG. 1. In most instances, the perforation(s) 170 are located within the oil layer 124 of the reservoir rock 120 if a petroleum well is at issue, although the perforations may be placed elsewhere as desired. Once the well has been perforated or fractured, the well is typically produced as either an open hole completion or with the use of production tubing 142, as known in the art.
A problem arises, however, in that reservoirs are dynamic systems and subject to various stimuli, few of which are in the control of the producer. As just one example, as a well produces fluid the location of the interfaces or boundaries of the fluids changes over time, as affected by various factors, such as the porosity and the permeability of the reservoir formation, the in-situ pore pressure, the rate at which the well is produced, and others.
As the locations of the boundaries change, the mix of produced fluids typically changes. An example of this is illustrated in FIG. 1, in which the initial oil-water contact location 125a moves upward to oil-water contact location 125b. As a result, the perforations 170 which were initially within the oil layer 124 may now lie, at least in part, within the water layer 126. The result is that more water and less oil may be produced in this well. This increases the cost of producing the well (e.g., increased costs to treat the excess water, reinject the water, etc.) just as the revenue generated (i.e., the amount of petroleum produced) decreases.
A phenomena related to the changing of the entire oil-water contact 125a is known as “water-coning.” Water coning is the change in the oil-water or gas-oil contact locations, often as a result of producing fluids from the well too quickly by using excessive drawdown pressures. Water-coning occurs in vertical or slightly deviated wells, i.e., wells that have a low angle of inclination relative to vertical, and is affected by the characteristics of the fluids involved and the ratio of horizontal to vertical permeability. When the well is horizontal or highly deviated, the phenomenon is known as “cresting.” Regardless of whether vertical or horizontal, the principles are the same. An example of water-coning is illustrated in FIG. 2. The initial water-oil contact location 125a changes from its initial configuration to a cone-shaped oil-water contact location 125b as the well is produced. As with FIG. 1, while the perforations 170 initially lie within the oil layer 124, once water-coning occurs the perforations 170 lie, in part, within the water layer 126.
The risk of water coning is partly diminished to some extent by carefully monitoring the locations of the fluid contacts and adjusting production rates accordingly in real-time. In addition, the accurate knowledge of the locations of the fluid contacts permits the design and execution of production treatments, such as additional perforation, fracturing, or the placement of packers to isolate non-productive zones, such as water producing zones in a petroleum well or saline zones in a fresh water well.
Unfortunately, the wireline or LWD tools that were used to make the initial measurements to identify fluid interfaces or boundaries in a well prior to production often cannot be used economically to make the same measurements while the well is producing. This is so because using wireline or LWD tools typically requires that the well to be shut-in (i.e., production stopped), resulting in a loss of revenue. Additionally, production tubing present in the well bore may have to be removed in order to run the wireline or LWD tools, leading to an even greater increase in cost and a longer time during which production and revenue is lost.
Considering the foregoing, it is therefore desirable to have a system that is capable of identifying and monitoring the location of an interface or boundary between different fluids in a producing well bore in real-time. In addition, it is desirable to have a system that minimizes or eliminates semiconductor and other electrical components in that portion of the system positioned in a well so as to reduce the risk of damage or failure resulting from exposure to temperature extremes, both high and low (in the case of nitrogen or carbon dioxide applications).